The formation of scales is a common problem in oil and gas wells. During the production of oil and gas, salt water is also produced. The produced water often contains high concentrations of alkaline earth metal cations such as calcium, strontium, and barium, along with anions such as carbonate, bicarbonate, and sulfate. Typically in areas of the oil or gas processing system where there is an abrupt physical change, such as a change in temperature or pressure, or a mixing of incompatible waters, there is a thermodynamic driving force for these inorganic salts to precipitate and form scales. These precipitations are known to form near the wellbore, inside casing, tubing, pipes, pumps and valves, and around heating coils. Reduction of near wellbore permeability, perforation tunnel diameter, production tubing diameter, and propped fracture conductivities can significantly reduce well productivity. Over time, large scale deposits can form reducing fluid flow and heat transfer as well as promoting corrosion and bacterial growth. As the deposits grow, the production rate decreases and even the whole operation could be forced to halt.
Removal of scales often requires expensive well interventions involving bullhead or coil tubing placement of scale dissolving chemical treatments, milling operations or re-perforation. Economically efficient scale management predominantly involves the application of chemical scale inhibitors that prevent scale deposition. Scale inhibitors are conventionally applied as downhole injections or squeeze treatments.
Threshold scale inhibitors are chemical agents that catalytically prevent salt precipitation, even when the brine is oversaturated. These chemicals are referred to as “threshold” scale inhibitors because they prevent nucleation and scale formation at concentrations that are far too low to be effective by stoichiometrically reacting with scale-forming ions alone, such as occurs with chelating agents. Threshold scale inhibitors are thought to achieve scale inhibition by adsorbing onto specific crystallographic planes of a growing crystal nucleus after a nucleation event. This adsorption prevents further crystal growth and agglomeration into larger aggregates.
Many aminophosphonate-based, scale inhibitors are known to the art. E.g., U.S. Pat. No. 3,434,969 (filed Aug. 11, 1967), U.S. Pat. No. 4,080,375 (filed Oct. 15, 1976), U.S. Pat. No. 4,931,189 (filed Jun. 15, 1989); U.S. Pat. No. 5,338,47 (filed May 11, 1992). However, a problem arises when the oilfield brines contain dissolved iron. Iron has been observed to have a deleterious effect on the performance of scale inhibitors. See e.g., G. M. Graham et al., The Impact of Dissolved Iron on the Performance of Scale Inhibitors Under Carbonate Scaling Conditions, Paper SPE 80254 presented at the International Symposium on Oilfield Chemistry, Houston, February 5-7; H. Guan et al., Inhibitor Selection for Iron-Scale Control in MEG Regeneration Process, November 2009 SPE Production & Operations. It has been found that many phosphonate-based scale inhibitors are particularly ineffective in the presence of iron. See Johnson, T. et al., Phosphonate Based Scale Inhibitors for High Iron and High Salinity Environments, Presented in Session 6 of the Royal Society of Chemistry Conference on Chemistry in the Oil Industry Manchester, UK, 31 October 2; Kriel, B. G. et al., The Effect of Soluble Iron on the Performance of Scale inhibitors in the Inhibition of Calcium Carbonate Scales Paper No. 44, presented at the NACE International CORROSION 94 March 1994; Coleman et al., Iron Release Following Scale Inhibitor Application and Mineral Dissolution in a North Alaskan Reservoir-Some Field Implications, paper presented at the SPE International Symposium on Oilfield Scale, Aberdeen, UK, 1999.
It would be a significant improvement to the industry to find a threshold scale inhibitor that can perform in oilfield waters containing dissolved iron.